The term “oil shale” refers to a sedimentary rock interspersed with an organic mixture of complex chemical compounds collectively referred to as “kerogen”. The oil shale consists of laminated sedimentary rock containing mainly clay minerals, quartz, calcite, dolomite, and iron compounds. Oil shale can vary in its mineral and chemical composition. When the oil shale is heated to above 260-370° C., destructive distillation of the kerogen (a process known as pyrolysis) occurs to produce products in the form of oil, gas, and residual char. The hydrocarbon products resulting from the pyrolysis of the kerogen have characteristics that are similar to that of other petroleum products. Oil shale is considered to have potential to become an important source for producing liquid fuels and natural gas, to supplement and augment those fuels currently produced from other petroleum sources.
Proposed in situ processes for recovering hydrocarbon products from oil shale resources describe treating the oil shale in the ground in order to recover the hydrocarbon products. These processes involve the circulation or injection of heat and/or solvents within a subsurface oil shale. Heating methods include hot gas or liquid injection, closed loop circulation of hot gas (e.g. flue gas, propane, methane or superheated steam), closed loop circulation of hot liquid, electric resistive heating, dielectric heating, microwave heating, downhole gas burners or oxidant injection to support in situ combustion. Permeability enhancing methods have been proposed including; rubblization, hydraulic fracturing, explosive fracturing, heat fracturing, steam fracturing, and/or the provision of multiple wellbores.
Heating fluids can be one of several types. A molten salt may be used, such as a nitrate or carbonate salt, or a mixture of such salts. An example of a heating fluid is a mixture of 60% NaNO3 and 40% KNO3 with a melting point of 220° C. This mixture can be heated to 450-650° C. before being piped into to the subsurface formation. The return temperature at the surface for reheating is typically around 250-500° C. Other classes of suitable salts include carbonates, halides or other well-known anions. The counterion (cation) should be environmentally benign, essentially in the form of alkali, alkaline earth elements or sink. A further option is an imidazolium based counterion if a low melting temperature is required. In general, a large size counterion gives a low melting point due to reduced coulomb interactions. The use of molten salts as a heat transfer fluid for heating a subsurface formation has been described in U.S. Pat. No. 7,832,484, which also includes several examples of such salts. Note that it is also possible, with due consideration of cracking effects, to use a hydrocarbon as heating medium. The hydrocarbon can be in a gaseous or liquid form.
The heating fluid is returned to the surface. In the surface facilities, the heating fluid is reheated after having been cooled down in the subsurface formation. Furthermore, it may be necessary to remove unwanted impurities in the heating fluid that have been picked up in the subsurface formation. Certain aspects of U-shaped wellbores containing heating fluid in a closed loop heating system have been described in WO 2006/116096.
In situ production of oil and gas from kerogen in the oil shale has not yet been carried out commercially. Both vertical and horizontal heating and production wells are described in various publications. Various configurations and geometries of patterns of heating wells and production wells have been proposed in an attempt to optimize heating of the subsurface formation.
A problem with the heating process is that that the heating rate is very slow. Heat is transported in the subsurface formation mainly by thermal conduction, and is limited by the low thermal conductivity of the oil shale. It is predicted that a subsurface formation may take years to come to suitable temperatures.
The slow and uneven heating rate in the oil shale formation can be addressed by providing a pattern of closely spaced heating wells. The heating wells must be a short distance to adjacent or nearby production wells in order to achieve production within a reasonable time. This high well density leads to high installation costs and high surface footprint.